This invention relates generally to the field of perforating and treating subterranean formations to enable the production of oil and gas therefrom. More specifically, the invention provides a method for perforating, isolating, and treating one interval or multiple intervals sequentially without need of a wireline or other running string.
In the drilling of oil and gas wells, a wellbore is formed using a drill bit that is urged downwardly at a lower end of a drill string. After drilling to a predetermined depth, the drill string and bit are removed and the wellbore is lined with a string of casing. An annular area is thus formed between the string of casing and the surrounding formations.
A cementing operation is typically conducted in order to fill or “squeeze” the annular area with cement. This serves to form a cement sheath. The combination of cement and casing strengthens the wellbore and facilitates the isolation of the formations behind the casing.
It is common to place several strings of casing having progressively smaller outer diameters into the wellbore. Thus, the process of drilling and then cementing progressively smaller strings of casing is repeated several or even multiple times until the well has reached total depth. The final string of casing, referred to as a production casing, is cemented into place. In some instances, the final string of casing is a liner, that is, a string of casing that is not tied back to the surface, but is hung from the lower end of the preceding string of casing.
As part of the completion process, the production casing is perforated at a desired level. This means that lateral holes are shot through the casing and the cement sheath surrounding the casing to allow hydrocarbon fluids to flow into the wellbore. Thereafter, the formation is typically fractured.
Hydraulic fracturing consists of injecting viscous fluids (usually shear thinning, non-Newtonian gels or emulsions) into a formation at such high pressures and rates that the reservoir rock fails and forms a network of fractures. The fracturing fluid is typically mixed with a granular proppant material such as sand, ceramic beads, or other granular materials. The proppant serves to hold the fracture(s) open after the hydraulic pressures are released. The combination of fractures and injected proppant increases the flow capacity of the treated reservoir.
In order to further stimulate the formation and to clean the near-wellbore regions downhole, an operator may choose to “acidize” the formations. This is done by injecting an acid solution down the wellbore and through the perforations. The use of an acidizing solution is particularly beneficial when the formation comprises carbonate rock. In operation, the drilling company injects a concentrated formic acid or other acidic composition into the wellbore, and directs the fluid into selected zones of interest. The acid helps to dissolve carbonate material, thereby opening up porous channels through which hydrocarbon fluids may flow into the wellbore. In addition, the acid helps to dissolve drilling mud that may have invaded the formation.
Application of hydraulic fracturing and acid stimulation as described above is a routine part of petroleum industry operations as applied to individual target zones. Such target zones may represent up to about 60 meters (200 feet) of gross, vertical thickness of subterranean formation. When there are multiple or layered reservoirs to be hydraulically fractured, or a very thick hydrocarbon-bearing formation (over about 40 meters), then more complex treatment techniques are required to obtain treatment of the entire target formation. In this respect, the operating company must isolate various zones to ensure that each separate zone is not only perforated, but adequately fractured and treated. In this way the operator is sure that fracturing fluid and/or stimulant is being injected through each set of perforations and into each zone of interest to effectively increase the flow capacity at each desired depth.
The isolation of various zones for pre-production treatment requires that the intervals be treated in stages. This, in turn, involves the use of so-called diversion methods. In petroleum industry terminology, “diversion” means that injected fluid is diverted from entering one set of perforations so that the fluid primarily enters only one selected zone of interest. Where multiple zones of interest are to be perforated, this requires that multiple stages of diversion be carried out.
In order to isolate selected zones of interest, various diversion techniques may be employed within the wellbore. Known diversion techniques include the use of:                Mechanical devices such as bridge plugs, packers, down-hole valves, sliding sleeves, and baffle/plug combinations;        Ball sealers;        Particulates such as sand, ceramic material, proppant, salt, waxes, resins, or other compounds;        Chemical systems such as viscosified fluids, gelled fluids, foams, or other chemically formulated fluids; and        Limited entry methods.        
These and other methods for temporarily blocking the flow of fluids into or out of a given set of perforations are described more fully in U.S. Pat. No. 6,394,184 entitled “Method and Apparatus for Stimulation of Multiple Formation Intervals.” The '184 patent issued in 2002 and was co-assigned to ExxonMobil Upstream Research Company. The '184 patent is referred to and incorporated herein by reference in its entirety.
The '184 patent also discloses various techniques for running a bottom hole assembly (“BHA”) into a wellbore, and then creating fluid communication between the wellbore and various zones of interest. In most embodiments, the BHA's include various perforating guns having associated charges. The BHA's further include a wireline extending from the surface and to the assembly for providing electrical signals to the perforating guns. The electrical signals allow the operator to cause the charges to detonate, thereby forming perforations.
The BHA's also include a set of mechanically actuated, re-settable axial position locking devices, or slips. The illustrative slips are actuated through a “continuous J” mechanism by cycling the axial load between compression and tension. The BHA's further include an inflatable packer or other sealing mechanism. The packer is actuated by application of a slight compressive load after the slips are set within the casing. The packer is resettable so that the BHA may be moved to different depths or locations along the wellbore so as to isolate selected perforations.
The BHA also includes a casing collar locator. The casing collar locator allows the operator to monitor the depth or location of the assembly for appropriately detonating charges. After the charges are detonated (or the casing is otherwise penetrated for fluid communication with a surrounding zone of interest), the BHA is moved so that the packer may be set at a desired depth. The casing collar locator allows the operator to move the BHA to an appropriate depth relative to the newly formed perforations, and then isolate those perforations for hydraulic fracturing and chemical treatment.
Each of the various embodiments for a BHA disclosed in the '184 patent includes a means for deploying the assembly into the wellbore, and then translating the assembly up and down the wellbore. Such translation means include a string of coiled tubing, conventional jointed tubing, a wireline, an electric line, or a downhole tractor. In any instance, the purpose of the bottom hole assemblies is to allow the operator to perforate the casing along various zones of interest, and then sequentially isolate the respective zones of interest so that fracturing fluid may be injected into the zones of interest in the same trip.
Known well completion processes require the use of surface equipment. FIG. 1 presents a side view of a well site 100 wherein a well is being drilled. The well site 100 is using known surface equipment 50 to support wellbore tools (not shown) above and within a wellbore 10. The wellbore tools may be, for example, a perforating gun or a fracturing plug. In the illustrative arrangement of FIG. 1, the wellbore tools are suspended at the end of a wireline 85.
The surface equipment 50 first includes a lubricator 52. The lubricator 52 is an elongated tubular device configured to receive wellbore tools (or a string of wellbore tools), and introduce them into the wellbore 10. In general, the lubricator 52 must be of a length greater than the length of the perforating gun assembly (or other tool string) to allow the perforating gun assembly to be safely deployed in the wellbore 100 under pressure.
The lubricator 52 delivers the tool string in a manner where the pressure in the wellbore 10 is controlled and maintained. With readily-available existing equipment, the height to the top of the lubricator 52 can be approximately 100 feet from an earth surface 105. Depending on the overall length requirements, other lubricator suspension systems (fit-for-purpose completion/workover rigs) may also be used. Alternatively, to reduce the overall surface height requirements, a downhole lubricator system similar to that described in U.S. Pat. No. 6,056,055 issued May 2, 2000 may be used as part of the surface equipment 50 and completion operations.
The lubricator 52 is suspended over the wellbore 10 by means of a crane arm 54. The crane arm 54 is supported over the earth surface 105 by a crane base 56. The crane base 56 may be a working vehicle that is capable of transporting part or the entire crane arm 54 over a roadway. The crane arm 54 includes wires or cables 58 used to hold and manipulate the lubricator 52 into and out of position over the wellbore 10. The crane arm 54 and crane base 56 are designed to support the load of the lubricator 52 and any load requirements anticipated for the completion operations.
In the view of FIG. 1, the lubricator 52 has been set down over a wellbore 10. An upper portion of an illustrative wellbore 10 is shown in FIG. 1. The wellbore 10 defines a bore 5 that extends from the surface 105 of the earth, and into the earth's subsurface 110.
The wellbore 10 is first formed with a string of surface casing 20. The surface casing 20 has an upper end 22 in sealed connection with a lower master fracture valve 25. The surface casing 20 also has a lower end 24. The surface casing 20 is secured in the wellbore 10 with a surrounding cement sheath 12.
The wellbore 10 also includes a string of production casing 30. The production casing 30 is also secured in the wellbore 10 with a surrounding cement sheath 14. The production casing 30 has an upper end 32 in sealed connection with an upper master fracture valve 35. The production casing 30 also has a lower end (not shown). It is understood that the depth of the wellbore 10 preferably extends some distance below a lowest zone or subsurface interval to be stimulated to accommodate the length of the downhole tool, such as a perforating gun assembly. The downhole tool is attached to the end of a wireline 85.
The surface equipment 50 also includes one or more blow-out preventers 60. The blow-out preventers 60 are typically remotely actuated in the event of operational upsets. The lubricator 52, the crane arm 54, the crane base 56, the blow-out preventers 60 (and their associated ancillary control and/or actuation components) are standard equipment components known to those skilled in the art of well completion.
As shown in FIG. 1, a wellhead 70 is provided above the earth surface 105. The wellhead 70 is used to selectively seal the wellbore 10. During completion, the wellhead 70 includes various spooling components, sometimes referred to as spool pieces. The wellhead 70 and its spool pieces are used for flow control and hydraulic isolation during rig-up operations, stimulation operations, and rig-down operations.
The spool pieces may include a crown valve 72. The crown valve 72 is used to isolate the wellbore 10 from the lubricator 52 or other components above the wellhead. The spool pieces also include the lower master fracture valve 25 and the upper master fracture valve 35, referenced above. These lower 25 and upper 35 master fracture valves provide valve systems for isolation of wellbore pressures above and below their respective locations. Depending on site-specific practices and stimulation job design, it is possible that one of these isolation-type valves may not be needed or used.
The wellhead 70 and its spool pieces may also include side outlet injection valves 74. The side outlet injection valves 74 provide a location for injection of stimulation fluids into the wellbore 10. The piping from surface pumps (not shown) and tanks (not shown) used for injection of the stimulation fluids are attached to the valves 74 using appropriate hoses, fittings and/or couplings. The stimulation fluids are then pumped into the production casing 30.
The wellhead 70 and its spool pieces may also include a wireline isolation tool 76. The wireline isolation tool 76 provides a means to protect the wireline 85 from direct flow of proppant-laden fluid injected into the side outlet injection valves 74. However, it is noted that the wireline 85 is generally not protected from the proppant-laden fluids below the wellhead 70. Because the proppant-laden fluid is highly abrasive, this creates a ceiling as to the pump rate for pumping the downhole tools into the wellbore 10.
It is understood that the various items of surface equipment 50 and components of the wellhead 70 are merely illustrative. A typical completion operation will include numerous valves, pipes, tanks, fittings, couplings, gauges, and other devices. Further, downhole equipment may be run into and out of the wellbore using an electric line, coiled tubing, or a tractor. Alternatively, a drilling rig or other platform may be employed, with jointed working tubes being used.
In any instance, there is a need for downhole tools that may be deployed within a wellbore without a lubricator and a crane arm. Further, a need exists for tools that may be deployed in a string of production casing or other tubular body such as a pipeline that are autonomous, that is, they are not mechanically controlled from the surface. Further, a need exists for methods for perforating and treating multiple intervals along a wellbore without being limited by pump rate or the need for an elongated lubricator.